The present invention relates to isokinetic sampling. It is particularly, but not exclusively, related to methods and apparatuses for carrying out isokinetic sampling, and in particular isokinetic sampling in oilfield applications.
In oilfield applications, as in many other fields, it is important to be able to analyse the composition and properties of a multi-phase fluid stream, such as a gas-condensate stream or a wet-gas stream. In particular it is desired to know the quantity of the various phases of the flow, for example by knowing the gas-oil ratio (GOR) or the condensate-gas ratio (CGR). It is also desired to know the properties of the various phases, for example their pressure, volume and temperature (PVT) relationships.
For example, the prediction of fluid phase behavior and reservoir simulation models based on equations-of-state (EOS) typically requires high quality PVT data.
PVT data are also often needed for flow assurance in wells and transport lines.
Furthermore, PVT data often have a significant impact on processing facility designs and specifications, and therefore on the profitability of gas-oil field.
However, to accurately determine the PVT properties and composition of reservoir fluid, representative fluid samples are required. Common analysis sampling procedures suffer from deficiencies in either or both of their accuracy and their ability to cope with high flow rates.
For example, a high-rate gas condensate well producing 5-100 MMscf (Millions standard cubic feet)/day with a gas-oil ratio of 3 k-100 k scf/bbl (CGR from 0 to 200 bbl/MMscf) (bbl=barrel of liquid; 1 m3=6.29 bbl), can often overwhelm a test-separator, causing liquid carry-over in the separator gas outlet line, thereby providing poor measurement of the GOR and non-representative PVT samples (if the carry-over is not measured and corrected for). This normally also results in poor recombination ratios. Gas condensate wells are particularly problematic for sampling as large volumes of gas are associated with only small volumes of liquid, and the phase behavior will be highly sensitive to the quantity and composition of the liquid phase.
Wellhead sampling is therefore considered to be the only practical method of obtaining reliable test data for such applications. Isokinetic sampling at a wellhead of a multiphase fluid is desirable since, if achieved, it means that the sample of the fluid is at the same pressure, temperature and velocity as the main flow stream, and therefore will have identical properties to that main flow stream.
A known wellhead sampling system is shown schematically in FIG. 1, which is taken from Dybdahl and Hjermstad “A systematic approach to sampling during well testing”, Society of Petroleum Engineers (SPE) paper 69427, SPE Latin America & Caribbean Petroleum Engineering Conference, Buenos, Argentina, 25-28 Mar. 2001 (see also the paper by Henk et al. “Testing of gas condensate reservoirs—sampling, test design and analysis”, SPE paper 68668, SPE Asia Pacific Oil & Gas Conference, Jakarta, Indonesia, 17-19 Apr. 2001). Such a system is, for example, produced by Petrotech under their IsoSplit™ wellhead sampling and separator sampling services.
The wellhead sampling system of FIG. 1 consists of two parts.
The first part is a wellhead mixing/sampling manifold 1010, which is positioned upstream of the choke manifold 1030, and has a focusing-action static mixing device 1015 (see GB 2301297 & U.S. Pat. No. 5,894,080; a similar mixing device is shown in FIG. 2a) for collecting liquid at the wall of the pipe and distributing it into the main flow stream. A sampling probe 1020 is radially inserted downstream of the mixer 1015 for withdrawing a sample of the main flow stream.
The second part is an on-site laboratory 1050 (also called a “Mini-lab”), which processes the sampled stream to measure the condensate-gas ratio (CGR). PVT samples for compositional characterization are taken.
As described in SPE paper 68668, the liquid distribution across the flow pipe of FIG. 1 will vary, and either a mixing device or a traversing probe has to be used in order to have a split stream sample with the correct gas condensate ratio. As described in SPE paper 69427, the probe traversing enables sampling at multiple points across the pipe and the subsequent correction for the droplet and velocity distribution. It is stated in SPE 68668 that the liquid collected from the wall by the focusing-action mixer 1015 is distributed homogeneously into the flowing gas stream. However, our own gas-liquid ratio (GLR) profile measurement shown in FIG. 2b, for a mixer design (shown in FIG. 2a) similar to the focussing-action mixer 1015, indicates a liquid-rich jet at the central region of the sampling cross section. The GLR measured at such points will be a gross under-estimate of the pipe average value. FIG. 2b shows a −70% error in the GLR at the pipe centre, with respect to the pipe reference GLR.
SPE paper 68668 also states that sample withdrawal through the sampling probe 20 from the main stream is performed at an isokinetic sampling rate, i.e. at the same linear velocity as the wellhead fluid stream, which is necessary to sample the gas and liquid phase in the correct ratio. This isokinetic sampling rate is said to be calculated from the probe size and the gas flow rate measured at the test separator.
This approach has at least the following disadvantages:                1) A test separator is needed for wellhead sampling operations, which is bulky and expensive (FIG. 1).        2) The test separator can be overwhelmed by high-rate gas wells, leading to liquid carry-over in the separator gas outlet line. This can result in an inaccurate main-stream gas rate measurement used to set the isokinetic sampling rate.        3) The main-flow gas rate can fluctuate, for example due to changes in the liquid loading. This unsteadiness in the main flow rate can cause the separator gas rate measurement to be unreliable (see SPE paper 76766, by B. C. Theuveny and P. Mehdizadeh “Multiphase flowmeter application for well and fiscal allocation”, Alaska, 20-22 May 2002), leading to unreliable isokinetic sampling.        4) Isokinetic sampling rate control based on measured main-stream gas flow rates can lead to errors when liquid loading becomes relatively high.        
WO00/49370 describes a method for measuring the liquid and gas flow rates of a multi-phase fluid stream including withdrawing a portion of the overall flow rate under “isokinetic conditions”. The sampled portion forms approximately 5% to 15% of the total flow rate.
The methods and apparatus disclosed in WO00/49370 do not independently measure the main flow stream, but instead derive measurements of the main flow stream from the effect of the sampling operation on the flow stream. Furthermore, although the methods described are claimed to be “isokinetic”, this term is applied to all sampling in which the ratio of the sampled flow rate to the calculated total flow rate is within 20% of the ratio of the cross sectional area of the sampling probe to the cross sectional area of the flow stream. Adjustment of the sampling conditions is only made if the ratio falls outside this range.
The method proposed in WO00/49370 for measuring the total flow rate (Q1) of the fluid stream is given in equation (5) of that application, with Q1 being calculated as the sole unknown in the equation
                    Δ        ⁢                                  ⁢                  p          1                            Δ        ⁢                                  ⁢                  p          2                      =                  (                              Q            1                                              Q              1                        -            q                          )            2        ,where q is the measured sampled flow rate and Δp1 and Δp2 are measured pressure differences of the main flow stream with and without sampling operating. This assumes that the density of the sampled flow q is the same as the density of the total flow Q1.
Thus Q1 is calculated as
      Q    1    =      q    ⁢                                        Δ            ⁢                                                  ⁢                                          p                1                            /              Δ                        ⁢                                                  ⁢                          p              2                                                                          Δ              ⁢                                                          ⁢                                                p                  1                                /                Δ                            ⁢                                                          ⁢                              p                2                                              -          1                    .      From this equation, the error δQ1 in Q1 can be determined as
                    (                              δ            ⁢                                                  ⁢                          Q              1                                            Q            1                          )            2        =                            (                                    δ              ⁢                                                          ⁢              q                        q                    )                2            +                        (                                                    δ                ⁢                                                                  ⁢                P                            P                        ⁢                          1                              P                -                1                                              )                2              ,where P=√{square root over (Δp1/Δp2)}. For P>>1,
            δ      ⁢                          ⁢              Q        1                    Q      1        ≈                    δ        ⁢                                  ⁢        q            q        .  However, as
                    Δ        ⁢                                  ⁢                              p            1                    /          Δ                ⁢                                  ⁢                  p          2                      →    1    ,                    δ        ⁢                                  ⁢                  Q          1                            Q        1              →          ∞      .      Therefore, in order to avoid excessive errors in the measurement of the total flow rate Q1 when using the method of WO00/49370 it is important that the difference between Δp1 and Δp2 is large, and consequently that the flow rate of the sampled flow is a substantial proportion (i.e. more than 5%) of the total flow rate. When such sampling proportions are used in high flow situations, for example in a high-rate gas condensate wells, they can overwhelm the separator, or alternatively require a larger, and therefore more expensive separator.